U.S. patent number 8,486,702 [Application Number 13/534,282] was granted by the patent office on 2013-07-16 for method of tracking fluids produced from various zones in subterranean well.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Johnny A. Barton, Philip D. Nguyen, Jimmie D. Weaver. Invention is credited to Johnny A. Barton, Philip D. Nguyen, Jimmie D. Weaver.
United States Patent |
8,486,702 |
Nguyen , et al. |
July 16, 2013 |
Method of tracking fluids produced from various zones in
subterranean well
Abstract
A traceable treatment composition for treating a subterranean
formation having multiple zones penetrated by a well bore
comprising a homogenous blend of a tracking composition and a resin
composition. The tracking composition comprises a substantially
non-radioactive tracking material selected from the group
consisting of a metal salt. The metal portion of the metal salt may
be selected from the group consisting of gold, silver, lithium,
molybdenum, and vanadium. The metal salt may also be selected from
the group consisting of: barium bromide, barium iodide, beryllium
fluoride, beryllium bromide, beryllium chloride, cadmium bromide,
cadmium iodide, chromium bromide, chromium chloride, chromium
iodide, cesium bromide, cesium chloride, sodium bromide, sodium
iodide, sodium nitrate, sodium nitrite, potassium iodide, potassium
nitrate, manganese bromide, zinc bromide, zinc iodide, sodium
monofluoroacetate, sodium trifluoroacetate, sodium
3-fluoropropionate, potassium monofluoroacetate, potassium
trifluoroacetate, and potassium 3-fluoropropionate.
Inventors: |
Nguyen; Philip D. (Duncan,
OK), Weaver; Jimmie D. (Duncan, OK), Barton; Johnny
A. (Marlow, OK) |
Applicant: |
Name |
City |
State |
Country |
Type |
Nguyen; Philip D.
Weaver; Jimmie D.
Barton; Johnny A. |
Duncan
Duncan
Marlow |
OK
OK
OK |
US
US
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
22418503 |
Appl.
No.: |
13/534,282 |
Filed: |
June 27, 2012 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20120264660 A1 |
Oct 18, 2012 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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10777412 |
Feb 12, 2004 |
8354279 |
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10298825 |
Apr 27, 2004 |
6725926 |
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10125171 |
Feb 17, 2004 |
6691780 |
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Current U.S.
Class: |
436/27; 507/934;
436/25; 436/31; 166/280.2; 507/203 |
Current CPC
Class: |
E21B
47/11 (20200501); C09K 8/805 (20130101); Y10S
507/907 (20130101); Y10S 507/924 (20130101) |
Current International
Class: |
G01N
33/28 (20060101); C09K 8/80 (20060101); E21B
47/10 (20120101) |
Field of
Search: |
;507/203,934
;436/25,27,31 ;166/280.2 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
Lewis, Richard J., Sr. (2002) Hawley's Condensed Chemical
Dictionary (14th Edition), John Wiley & Sons, Online @
http://knovel.com/web/portal/browse/display?.sub.--EXT.sub.--KNOVEL.sub.--
-DISPLAY.sub.--bookid=704&VerticalID=0 , headword=A-stage
resin, (Knovel Release Date: Sep. 4, 2003; downloaded Aug. 26,
2012), pp. 1. cited by examiner.
|
Primary Examiner: Metzmaier; Daniel S
Attorney, Agent or Firm: Kent; Robert A. McDermott Will
& Emery LLP
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
This application is a divisional application of co-pending U.S.
patent application Ser. No. 10/777,412, filed Feb. 12, 2004 and
published as U.S. 2004/0162224, the entire disclosure of which is
incorporated herein by reference, and which itself is a divisional
application of U.S. patent application Ser. No. 10/298,825, filed
Nov. 18, 2002 and now patented as U.S. Pat. No. 6,725,926, the
entire discloser of which is incorporated herein by reference, and
which itself is a continuation-in-part of U.S. patent application
Ser. No. 10/125,171, filed Apr. 18, 2002 and now patented as U.S.
Pat. No. 6,691,780, the entire disclosure of which is incorporated
herein by reference.
Claims
What is claimed is:
1. A traceable treatment composition for treating a subterranean
formation having multiple zones penetrated by a well bore
comprising a homogenous blend of a tracking composition and a
liquid, hardenable resin composition, and wherein the tracking
composition comprises a substantially non-radioactive tracking
material selected from the group consisting of: metal salt wherein
a metal portion of the metal salt is vanadium; and, a metal salt
selected from the group consisting of barium bromide, barium
iodide, chromium bromide, chromium chloride, chromium iodide,
manganese bromide, sodium monofluoroacetate, sodium
trifluoroacetate, sodium 3-fluoropropionate, potassium
monofluoroacetate, potassium trifluoroacetate, and potassium
3-fluoropropionate; and, wherein the traceable treatment
composition is capable of being detected in a fluid produced from a
subterranean formation.
2. A traceable treatment composition according to claim 1 further
comprising a treatment fluid selected from the group consisting of
fracturing fluids, drilling fluids, disposal fluids and injection
fluids.
3. A traceable treatment composition according to claim 1, wherein
the treatment composition further comprises a particulate material
having a tracking material coated thereon.
4. A traceable treatment composition according to claim 1, further
comprising a particulate material associated with the tracking
material, and wherein the particulate material is selected from the
group consisting of fibrous materials and deformable beads.
Description
BACKGROUND
The present embodiment relates generally to the recovery of
hydrocarbons from a subterranean formation penetrated by a well
bore and more particularly to non-radioactive compositions and
methods of utilizing the non-radioactive compositions for
determining the source of treatment fluids being produced from a
production formation having multiple zones. For example, the
compositions and methods can be utilized for tracking the transport
of particulate solids during the production of hydrocarbons from a
subterranean formation penetrated by a well bore.
Transport of particulate solids during the production of
hydrocarbons from a subterranean formation penetrated by a well
bore is a continuing problem. The transported solids can erode or
cause significant wear in the hydrocarbon production equipment used
in the recovery process. The solids also can clog or plug the well
bore thereby limiting or completely stopping fluid production.
Further, the transported particulates must be separated from the
recovered hydrocarbons adding further expense to the processing.
The particulates which are available for transport may be present
due to an unconsolidated nature of a subterranean formation and/or
as a result of well treatments placing particulates in a well bore
or formation, such as, by gravel packing or propped fracturing.
In the treatment of subterranean formations, it is common to place
particulate materials as a filter medium and/or a proppant in the
near well bore area and in fractures extending outwardly from the
well bore. In fracturing operations, proppant is carried into
fractures created when hydraulic pressure is applied to these
subterranean rock formations to a point where fractures are
developed. Proppant suspended in a viscosified fracturing fluid is
carried outwardly away from the well bore within the fractures as
they are created and extended with continued pumping. Upon release
of pumping pressure, the proppant materials remain in the fractures
holding the separated rock faces in an open position forming a
channel for flow of formation fluids back to the well bore.
Proppant flowback is the transport of proppants back into the well
bore with the production of formation fluids following fracturing.
This undesirable result causes undue wear on production equipment,
the need for separation of solids from the produced hydrocarbons
and occasionally also decreases the efficiency of the fracturing
operation since the proppant does not remain within the fracture
and may limit the width or conductivity of the created flow
channel.
Current techniques for controlling the flowback of proppants
include coating the proppants with curable resin, or blending the
proppants with fibrous materials, tackifying agents or deformable
particulates (See e.g. U.S. Pat. No. 6,328,105 to Betzold, U.S.
Pat. No. 6,172,011 to Card et al. and U.S. Pat. No. 6,047,772 to
Weaver et al.) For a multi-zone well that has been fractured with
proppant and is plagued with proppant flowback problems, it is
quite difficult to identify the zone from which the proppant is
emanating unless the proppant is tagged with a tracer. Radioactive
materials have been commonly used in the logging or tagging of sand
or proppant placement, however, such radioactive materials are
hazardous to the environment and the techniques for utilizing such
radioactive materials are complex, expensive and time consuming.
Therefore, there is a need for simple compositions and methods for
tracking the flowback of proppant in subterranean wells to avoid
the above problems.
DETAILED DESCRIPTION
According to one embodiment, to determine from which zone(s) a
fluid is being produced, a water soluble inorganic or organic salt
is dissolved in the base treatment fluid as the fluid is being
pumped downhole during the treatment. Such treatment fluids include
but are not limited to fracturing fluids, drilling fluids, disposal
fluids and injection fluids used as displacement fluids in
hydrocarbon recovery processes. Acting as a fluid tracer agent, a
salt is tagged into the fluid that is unique for each treatment job
such as a fracturing job treatment. Suitable water soluble salts
for this purpose are metal salts in which the metal is selected
from Groups I to VIII of the Periodic Table of the Elements as well
as the lanthanide series of rare earth metals so long as the metal
salts do not constitute a component of fluids naturally present in
the formation and are compatible with the fluids injected into the
formation. Preferred metals include barium, beryllium, cadmium,
chromium, cesium, sodium, potassium, manganese and zinc.
Particularly preferred water soluble salts include barium bromide,
barium iodide, beryllium fluoride, beryllium bromide, beryllium
chloride, cadmium bromide, cadmium chloride, cadmium iodide,
cadmium nitrate, chromium bromide, chromium chloride, chromium
iodide, cesium bromide, cesium chloride, sodium bromide, sodium
iodide, sodium nitrate, sodium nitrite, potassium iodide, potassium
nitrate, manganese bromide, manganese chloride, zinc bromide, zinc
chloride, zinc iodide, sodium monofluoroacetate, sodium
trifluoroacetate, sodium 3-fluoropropionate, potassium
monofluoroacetate, potassium trifluoroacetate, potassium
3-fluoropropionate.
The fluid tracer agents used in the method of this embodiment must
meet a number of requirements. They should be relatively
inexpensive, must be compatible with fluids naturally present in
the reservoir and within the rock itself, as well as be compatible
with the fluids injected into the reservoir as part of the
formation treatment. The fluid tracer agents must be susceptible to
being readily detected qualitatively and analyzed quantitatively in
the presence of the materials naturally occurring in the formation
fluids. For example, an aqueous sodium chloride solution could be
utilized as a fluid tracer agent but for the fact that most field
brines contain sodium chloride in substantial quantities, and so
detection and analysis to differentiate the presence of sodium
chloride used as tracer in the presence of naturally-occurring
sodium chloride would be difficult.
In field application, a known amount of a selected water soluble
salt based on a known concentration (i.e. 100 parts per million) is
dissolved in a volume of water which is 1/1,000 of the total actual
volume of base fluid required for the treatment. The mixed solution
is then metered to the base fluid line at a rate of one gallon per
1,000 gallons of the base fluid. To handle multiple zones, various
salts can be used provided that the interest cations or anions of
selected compounds are unique to prevent any interference between
zones.
According to another embodiment, metals are tagged onto proppant
material or materials to be blended with proppant material to
provide for the ready identification of flowback proppant from
different stages or zones of the well. Suitable metals for this
purpose may be selected from Groups I to VIII of the Periodic Table
of the elements as well as the lanthanide series of rare earth
metals so long as the metals do not constitute a component of the
proppant, the fracturing fluid or the reservoir fluid and so long
as the metals are compatible with the fracturing fluid. Preferred
metals include gold, silver, copper, aluminum, barium, beryllium,
cadmium, cobalt, chromium, iron, lithium, magnesium, manganese,
molybdenum, nickel, phosphorus, lead, titanium, vanadium and zinc
as well as derivatives thereof including oxides, phosphates,
sulfates, carbonates and salts thereof so long as such derivatives
are only slightly soluble in water so that they remain intact
during transport with the proppant from the surface into the
fractures. Particularly preferred metals include copper, nickel,
zinc, cadmium, magnesium and barium. The metal acts as a tracer
material and a different metal is tagged onto the proppant, or onto
the materials to be blended with the proppant, so that each
proppant stage or each fracturing job treatment can be identified
by a unique tracer material. Suitable metals for use as the tracer
material are generally commercially available from Sigma-Aldrich,
Inc. as well as from Mallinckrodt Baker, Inc. It is understood,
however, that field grade materials may also be used as suitable
tracer materials for tagging onto proppant material or materials to
be blended with proppant material.
Samples of flowback proppant collected from the field may be
analyzed according to a process known as the inductively-coupled
plasma (ICP) discharge method to determine from which proppant
stage and which production zone the proppant has been produced.
According to the ICP discharge method, an aqueous sample is
nebulized within an ICP spectrometer and the resulting aerosol is
transported to an argon plasma torch located within the ICP
spectrometer. The ICP spectrometer measures the intensities of
element-specific atomic emissions produced when the solution
components enter the high-temperature plasma. An on-board computer
within the ICP spectrometer accesses a standard calibration curve
to translate the measured intensities into elemental
concentrations. ICP spectrometers for use according to the ICP
discharge method are generally commercially available from the
Thermo ARL business unit of Thermo Electron Corporation, Agilent
Technologies and several other companies. Depending upon the model
and the manufacturer, the degree of sensitivity of currently
commercially available ICP spectrometers can generally detect
levels as low as 1 to 5 parts per million for most of the metals
listed above.
It is understood that depending on the materials used as tagging
agents, other spectroscopic techniques well known to those skilled
in the art, including atomic absorption spectroscopy, X-ray
fluorescence spectroscopy, or neutron activation analysis, can be
utilized to identify these materials.
According to yet another embodiment, an oil-soluble or
oil-dispersible tracer comprising a metal salt, metal oxide, metal
sulfate, metal phosphate or a metal salt of an organic acid can be
used to tag the proppant by intimately mixing the metal with a
curable resin prior to coating the curable resin onto the proppant.
Preferably, the metal is selected from the Group VIB metals, the
Group VIIB metals, and the lanthanide series of rare earth metals.
Specifically, the metal according to this embodiment may be
chromium, molybdenum, tungsten, manganese, technetium, rhenium,
lanthanum, cerium, praseodymium, neodymium, promethium, samarium,
europium, gadolinium, terbium, dysprosium, holmium, erbium,
thulium, ytterbium and lutetium. It is preferred that the metals
according to this embodiment, do not constitute a component of the
proppant, the fracturing fluid or the reservoir fluid, and that the
metals are compatible with the fracturing fluid.
Preferably, the organic acid is a substituted or unsubstituted
carboxylic acid. More preferably, the organic acid may be selected
from alkanoic and alkenoic carboxylic acids, polyunsaturated
aliphatic monocarboxylic acids and aromatic carboxylic acids. Most
preferably, the alkanoic carboxylic acids have from 5 to 35 carbon
atoms, the alkenoic carboxylic acids have from 5 to 30 carbon
atoms, the polyunsaturated aliphatic monocarboxylic acids may be
selected from the group of sorbic, linoleic, linolenic, and
eleostearic acids and the aromatic acids may be selected from the
group of benzoic, salicylic, cinnamic and gallic acids. Suitable
organic acids are generally commercially available from
Sigma-Aldrich, Inc. as well as from Mallinckrodt Baker, Inc.
For proppant to be coated with a curable resin, the tracer agent is
blended homogeneously with the resin mixture and the resin is then
coated onto the proppant. The proppant can be pre-coated as in the
case of curable resin-coated proppants, for example, such as those
commercially available from Santrol or Acme Borden, or it can be
coated on-the-fly during the fracturing job treatment. The nature
of the resin materials and the processes for performing the coating
process is well know to those skilled in the art, as represented by
U.S. Pat. No. 5,609,207 to Dewprashad et al., the entire disclosure
of which is hereby incorporated herein by reference. Also, it is
understood that materials to be blended with proppant such as the
fibrous materials, tackifying agents or deformable beads disclosed
in U.S. Pat. No. 6,328,105 to Betzold, U.S. Pat. No. 6,172,011 to
Card et al. and U.S. Pat. No. 6,047,772 to Weaver et al., the
entire disclosures of which are hereby incorporated by reference,
can be similarly treated with a tracer agent.
According to still another embodiment, the metal elements or their
derivative compounds can be tagged as part of the manufacturing
process of proppant. As a result, the proppant is tagged with a
permanent tracer.
According to yet another embodiment, the proppant can be coated
with phosphorescent, fluorescent, or photoluminescent pigments,
such as those disclosed in U.S. Pat. No. 6,123,871 to Carroll, U.S.
Pat. No. 5,498,280 to Fistner et al. and U.S. Pat. No. 6,074,739 to
Katagiri, the entire disclosures of which are hereby incorporated
herein by reference. According to this embodiment, the
phosphorescent, fluorescent, or photoluminescent pigments maybe
prepared from materials well known to those skilled in the art
including but not limited to alkaline earth aluminates activated by
rare earth ions, zinc sulfide phosphors, aluminate phosphors, zinc
silicate phosphors, zinc sulfide cadmium phosphors, strontium
sulfide phosphors, calcium tungstate phosphors and calcium sulfide
phosphors. Suitable phosphorescent, fluorescent and
photoluminescent materials are commercially available from Keystone
Aniline Corporation (TB Series) and Capricorn Chemicals (H Series
and S Series Glowbug Specialty Pigments). The particular structure
of the materials has a strong capacity to absorb and store visible
light such as sunlight or light from artificial lighting. After
absorbing a variety of such common visible light the
phosphorescent, fluorescent, or photoluminescent materials will
glow in the dark. Various pigment colors can be combined with the
luminescent capability of the materials to enhance the
differentiation of the stages or zones. According to this
embodiment, micron sized particles of the phosphorescent,
fluorescent, or photoluminescent materials are intimately mixed
with a resin to be coated onto a proppant to be used in a
fracturing treatment.
According to still another embodiment, proppant materials having a
naturally dark color can be dyed or coated with a marker material
having a bright, vivid and intense color which marker material may
be selected from oil soluble dyes, oil dispersible dyes or oil
dispersible pigments. Suitable oil soluble dyes, oil dispersible
dyes and oil dispersible pigments are well known to those skilled
in the art and are generally commercially available from Keystone
Aniline Corporation and Abbey Color. According to this embodiment,
proppant materials having a dark color, such as bauxite proppant
which is naturally black in color, are dyed or coated with such
marker materials. In this regard, reference is made to the dyes
disclosed in U.S. Pat. No. 6,210,471 to Craig, the entire
disclosure of which is hereby incorporated herein by reference.
According to all of the above-described embodiment, the proppant
material may comprise substantially any substrate material that
does not undesirably chemically interact with other components used
in treating the subterranean formation. It is understood that the
proppant material may comprise sand, ceramics, glass, sintered
bauxite, resin coated sand, resin beads, metal beads and the
like.
The following examples are illustrative of the methods and
compositions discussed above.
EXAMPLE 1
ZnCl.sub.2 was selected to tag 50,000 gallons of a base fracturing
fluid. For a 100-ppm concentration of ZnCl.sub.2 in the fracturing
fluid, it requires 0.2084 gram per liter of fluid, or 39.44 kg for
the total fluid volume. This amount of ZnCl.sub.2 is dissolved in
50 gallons of fluid, and the mixed solution is metered into the
base fluid line at a rate of 1 gallon for every 1,000 gallons of
the base fluid.
A number of methods well known to those of ordinary skill in the
art such as wet chemistry titration, colorimetry, atomic absorption
spectroscopy, inductively coupled plasma (ICP) discharge, ion
chromatography (IC), gas chromatography (GC), liquid chromatography
(LC) and nuclear magnetic resonance (NMR), can be used to analyze
the fluid samples produced from the well and to determine from
which zones the fluid has been produced, and the theoretical
production level of each zone in the well.
EXAMPLE 2
A total of three separate hydraulic fracturing treatments were
performed in a subterranean formation penetrated by a well bore.
For each fracturing treatment, sufficient metal tracer was added to
a liquid hardenable resin to provide an initial concentration of
1000 ppm of the metal tracer in the resin treated proppant. Cuprous
oxide, manganese oxide, and zinc oxide were used as tagging agents
in fracturing treatments 1, 2, and 3, respectively. Samples of
flowback proppant were collected during the flow back of the well.
Each proppant sample was weighted and digested in concentrated
nitric acid before being measured against known, calibrated metal
concentrations according to the inductively coupled plasma (ICP)
discharge method for the ARL Model 3410 ICP which is commercially
available from the Thermo ARL business unit of Thermo Electron
Corporation. Table 1 shows the concentrations of each metal
obtained in each proppant flowback sample. The data indicated that
the highest concentration of flowback proppant was produced from
the interval of the well that was fractured in the second
fracturing treatment.
TABLE-US-00001 TABLE 1 Frac Treatment 1 Frac Treatment 2 Frac
Treatment 3 Sample Number Cu (ppm) Mn (ppm) Zn (ppm) 1 1.9 217.3
11.5 2 2 219.2 11.8 3 2.8 120.5 9.1 4 3.1 204.1 12 5 670.6 382 24.1
6 51.6 214.1 15.3 7 7.3 234.5 13.3 8 2.7 437.7 17.1 9 2.3 183.8
11.9 10 2.7 220.2 12.8 11 2.9 465 19.3 12 2.1 408.1 17.4 13 2.7
577.2 19.3 14 3.1 410.2 18.2 15 2.3 342.9 40.2 16 2.1 299.8 14.9 17
6.5 296.8 12.5 18 2.1 494.8 18 19 51 385.8 16.5 20 2.7 443.8 17 21
2.8 564.8 44.6 22 35.5 551.8 16.1 23 2.4 545.8 23.3 24 2 538.8 14.7
25 181 342.8 16.6 26 1.5 119.8 10.3 27 1.4 34.8 11.9 28 1.9 204.8
43.2 29 2 240.8 13.7 30 2.4 175.8 11.3 31 7.5 171.8 10.9 32 2.3
57.8 7.7 33 5.8 192.8 17 34 1.7 188.8 12.1 35 1.9 115.8 9.6 36 2.1
168.9 11.1 37 1.6 245.3 13 38 1.7 173.9 11.6 39 1.9 219.4 12.9 40
1.9 224.6 12.6 41 2 383.3 17.1 42 1.7 284.7 12.5 43 1.9 270.6 13.4
44 2.4 311 12.7 45 1.9 177.1 10.3 46 1.8 304.2 12.9 47 2.4 343.2
13.3 48 2 308.2 12.6 49 5.4 241.6 11.2 50 3.4 209.1 11.4 51 3.3
217.1 11.1 52 1.9 299.7 12.7 53 2.3 228.6 11.4 54 1.5 162.8
10.1
EXAMPLE 3
A total of five separate hydraulic fracturing treatments were
performed in a subterranean formation penetrated by a well bore.
For each fracturing treatment, sufficient metal tracer was added to
the liquid hardenable resin to provide an initial concentration of
1000 ppm of the metal tracer in the resin treated proppant.
Manganese oxide, cuprous oxide, zinc oxide, magnesium oxide, and
barium oxide were used as tagging agents in fracturing treatments 1
through 5, respectively. Samples of flowback proppant were
collected during the flow back of the well. Each proppant sample
was weighted and digested in concentrated nitric acid before being
measured against known, calibrated metal concentrations according
to the inductively coupled plasma (ICP) discharge method for the
ARL Model 3410 ICP which is commercially available from the Thermo
ARL business unit of Thermo Electron Corporation. Table 2 shows the
concentrations of each metal obtained in each proppant flowback
sample. The data indicated that the highest concentration of
flowback proppant was produced from the intervals of the well that
were fractured in fracturing treatments 1 and 5.
TABLE-US-00002 TABLE 2 Frac Frac Frac Frac Frac Treatment Treatment
Treatment Treatment Treatment Sample 1 2 3 4 5 Number Mn (ppm) Cu
(ppm) Zn (ppm) Mg (ppm) Ba (ppm) 1 256.9 7.3 18.2 26.8 106.2 2
210.3 14.5 23.1 24 110.6 3 164.5 12.4 20.2 22.5 94.8 4 236.5 9.1
19.9 23.3 100.4 5 97.8 10.5 14.7 19 105.7 6 288.9 2.8 15.8 25.4
110.4 7 202.8 172.8 12.1 21.3 99.7 8 221.3 3 12.8 22.3 115.9 9
167.9 2.9 12.5 21.8 115.7 10 236.1 2.2 12.5 22.8 90.7 11 162.6 1.6
10.8 19.5 85.9 12 111.8 1.6 8.9 18.8 74.9 13 231.8 1.7 11.5 21.7
86.7 14 246.9 2.5 13.1 24.4 98.3 15 348.2 2 13.5 26.8 112.8 16
273.5 2.4 12.4 24.4 101 17 221.5 2 11.4 29.3 83.8 18 268 1.4 11.9
25.8 88.4 19 177.8 1.8 10.4 22.3 77.8 20 247.5 2.4 11.3 28 92.2 21
132.8 1.8 10 22.2 72.4 22 165.8 2.3 9.4 20.9 75.3 23 306.9 66.4
11.9 28.7 103.8 24 205.7 1.6 9.4 23 87.1 25 241.2 2.6 10.6 23.4
90.4 26 197.6 2.2 10.1 24.1 88 27 242 2.3 10.7 26.2 98.9 28 202.8 3
10.8 24.6 94.6 29 165.7 2 9 20.7 85.5 30 138.3 1.4 8.7 21.3 76.1 31
227.4 1.5 10.3 24 92.8 32 192.1 1.7 9.8 23.5 86.6 33 201.9 1.2 9.6
22.3 86.4 34 138.4 1.7 8.6 19.8 73.9
VARIATIONS AND EQUIVALENTS
Although only a few exemplary embodiments have been described in
detail above, those skilled in the art will readily appreciate that
many other modifications are possible in the exemplary embodiments
without materially departing from the novel teachings and
advantages described herein. Accordingly, all such modifications
are intended to be included within the scope of the following
claims.
* * * * *
References